Control of fine particulate flowback in subterranean wells

ABSTRACT

The present invention provides a method of treating a wellbore penetrating a subterranean formation with a treatment fluid whereby fine particulate flowback is reduced or prevented. The method includes the steps of providing a fluid suspension including a mixture of a particulate coated with a tackifying compound, pumping the suspension into a subterranean formation and depositing the mixture within the formation whereby the tackifying compound retards movement of at least a portion of any fine particulate within the formation upon flow of fluids from the subterranean formation through the wellbore. Alternatively, the tackifying compound may be introduced into a subterranean formation in a diluent containing solution to deposit upon previously introduced particulates to retard movement of such particulates and any fines subject to flow with production of fluids from the subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present Application is a Divisional Application of U.S. applicationSer. No. 08/858,312 filed May 19, 1997, now U.S. Pat. No. 5,775,425,which is a Continuation-in-Part of U.S. application Ser. No. 08,725,368filed Oct. 3, 1996, now U.S. Pat. No. 5,787,986, which is aContinuation-in-Part of U.S. application Ser. No. 08/510,399 filed Aug.2, 1995, now U.S. Pat. No. 5,582,249, which is a Continuation-in-Part ofU.S. application Ser. No. 08/412,668 filed Mar. 29, 1995, now U.S. Pat.No. 5,501,274.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to means for recovering hydrocarbons from asubterranean formation and more particularly to a method and means forcontrolling transport of fine particulate solids produced during astimulation treatment during the subsequent production of hydrocarbonsfrom a subterranean formation.

2. Brief Description of the Prior Art

Transport of particulate solids during the production of hydrocarbonsfrom a subterranean formation is a continuing problem. The transportedsolids can erode or cause significant wear in the hydrocarbon productionequipment used in the recovery process. The solids also can clog or plugthe wellbore thereby limiting or completely stopping fluid production.Further, the transported particulates must be separated from therecovered hydrocarbons adding further expense to the processing.

The particulates which are available for transport may be present due tothe nature of a subterranean formation and/or as a result of wellstimulation treatments wherein proppant is introduced into asubterranean formation

In the treatment of subterranean formations, it is common to placeparticulate materials as a filter medium and/or a proppant in the nearwellbore area and in fractures extending outwardly from the wellbore. Infracturing operations, proppant is carried into fractures created whenhydraulic pressure is applied to these subterranean rock formations to apoint where fractures are developed. Proppant suspended in a viscosifiedfracturing fluid is carried outwardly away from the wellbore within thefractures as they are created and extended with continued pumping. Uponrelease of pumping pressure, the proppant materials remain in thefractures holding the separated rock faces in an open position forming achannel for flow of formation fluids back to the wellbore.

Introduction of the proppant materials into the fracturing fluid oftenresults in the crushing of some portion of the proppant material as itpasses through the pumping and mixing equipment to enter thesubterranean formation. This fine crushed material may have a particlesize ranging from slightly below the size of the original proppantmaterial to less than 600 mesh on the U.S. Sieve Series. Also, when theformation closes at the conclusion of the treatment some crushing of theproppant material may occur producing additional fines. Even whenproppant crushing does not occur, the subterranean formation may itselfrelease fines from the face of the created fractures as a result ofspalling, scouring of the formation wall which causes formationparticulate to be mixed with the proppant and the like. These fineformation materials also may range from formation grain size to lessthan 600 mesh. The fines may comprise sand, shale or hydrocarbons suchas coal fines from coal degasification operations and the like. When thewellbore subsequently is produced, the fines tend to move into theproppant pack in the fracture tending to reduce the permeability of thepack. The fines also can flow with any production from the wellbore tothe surface.

This undesirable result causes undue wear on production equipment andthe need for separation of solids from the produced hydrocarbons. Finesflowback often may be aggravated by what is described as "aggressive"flowback of the well after a stimulation treatment. Aggressive flowbackgenerally entails flowback of the treatment fluid at a rate of fromabout 0.001 to about 0.1 barrels per minute (BPM) per perforation of thetreatment fluids which were introduced into the subterranean formation.Such flowback rates accelerate or force closure of the formation uponthe proppant introduced into the formation. The rapid flowrate canresult in large quantities of fines flowing back into the near wellboreas closure occurs causing permeability loss within the formation. Therapid flowback is highly desirable for the operator as it returns awellbore to production of hydrocarbons significantly sooner than wouldresult from other techniques.

Currently, the primary means for addressing the formation particulate orfines problem is to employ resin-coated proppants or resin consolidationof the proppant which is not capable of use in aggressive flowbacksituations. Further, the cost of resin-coated proppant is high, and istherefore used only as a tail-in in the last five to twenty five percentof the proppant placement. Resin-coated proppant is not always effectiveat forming a filtration bed since there is some difficulty in placing ituniformly within the fractures and, additionally, the resin coating canhave a deleterious effect on fracture conductivity. Resin coatedproppant also may interact chemically with common fracturing fluidcrosslinking systems such as guar or hydroxypropylguar withorgano-metallics or borate crosslinkers. This interaction results inaltered crosslinking and/or break times for the fluids thereby affectingplacement.

In unconsolidated formations, it is common to place a filtration bed ofgravel in the near-wellbore area in order to present a physical barrierto the transport of unconsolidated formation fines with the productionof hydrocarbons. Typically, such so-called "gravel packing operations"involve the pumping and placement of a quantity of gravel and/or sandhaving a mesh size between about 10 and 60 mesh on the U.S. StandardSieve Series into the unconsolidated formation adjacent to the wellbore.Sometimes multiple particle size ranges are employed within the gravelpack. It is sometimes also desirable to bind the gravel particlestogether in order to form a porous matrix through which formation fluidscan pass while straining out and retaining the bulk of theunconsolidated sand and/or fines transported to the near wellbore areaby the formation fluids. The gravel particles may constitute aresin-coated gravel which is either pre-cured or can be cured by anoverflush of a chemical binding agent once the gravel is in place. Ithas also been known to add various hardenable binding agents orhardenable adhesives directly to an overflush of unconsolidated gravelin order to bind the particles together. Various other techniques alsoare described in U.S. Pat. No. 5,492,178, the entire disclosure of whichis incorporated herein by reference.

U. S. Pat. Nos. 5,330,005, 5,439,055 and 5,501,275 disclose a method forovercoming the difficulties of resin coating proppants or gravel packsby the incorporation of a fibrous material in the fluid with which theparticulates are introduced into the subterranean formation. The fibersgenerally have a length ranging upwardly from about 2 millimeters and adiameter of from about 6 to about 200 microns. Fibrillated fibers ofsmaller diameter also may be used. The fibers are believed to act tobridge across constrictions and orifices in the proppant pack and form amat or framework which holds the particulates in place thereby limitingparticulate flowback. The fibers typically result in a 25 percent orgreater loss in permeability of the proppant pack that is created incomparison to a pack without the fibers.

While this technique may function to limit some flowback, it fails tosecure the particulates to one another in the manner achieved by use ofresin coated particulates.

U.S. Pat. No. 5,551,514 discloses a method for sand control thatcombines resin consolidation and placement of a fibrous material inintimate mixture with the particulates to enhance production without agravel pack screen.

It would be desirable to provide a method which will bind greaternumbers of fines particles to the proppant material in such a mannerthat it further assists in preventing movement or flowback ofparticulates from a wellbore or formation without significantly reducingthe permeability of the particulate pack during aggressive flowback oftreatment fluids.

BRIEF SUMMARY OF THE INVENTION

The present invention provides a method and fluid for treating asubterranean formation and a resultant porous particulate pack thatinhibits the flow of fine particulates back through the wellbore withthe production of hydrocarbons without significant effects upon thepermeability of the particulate pack.

In accordance with a preferred embodiment of the invention, a method oftreating a subterranean formation penetrated by a wellbore is providedcomprising the steps of providing a fluid suspension including a mixtureof particulate material and another material comprising a liquid orsolution of a tackifying compound, which coats at least a portion of theparticulate upon admixture therewith, pumping the fluid suspensionincluding the coated particulate through the wellbore and depositing themixture in the formation. Upon deposition of the coated material mixturein the formation the coating causes fine particulate adjacent the coatedmaterial to adhere upon contact with the coated material therebycreating agglomerates which bridge against other particles in theformation to prevent particulate flowback and fines migration. Thetackifying compound also may be introduced into the subterraneanformation prior to or after introduction of the proppant particulate.

The coated material is effective in inhibiting the flowback of fineparticulate in a porous pack having a size ranging from about that ofthe proppant material to less than about 600 mesh in intimate admixturewith the tackifying compound coated particulates.

The coated material is effective in consolidating fine particulate inthe form of agglomerates in a formation as a result of a fracturing orgravel packing treatment performed on a subterranean formation duringaggressive flowback of the treatment fluid.

BRIEF DESCRIPTION OF THE DRAWING FIGURES

FIG. 1 provides a schematic illustration of the test apparatus utilizedto determine the critical resuspension velocity for a coated substratematerial.

FIG. 2 provides a graphical illustration of sample permeability.

FIGS. 3A and 3B provide photomicrographs of untreated and treatedsamples illustrating fines retention.

DETAILED DESCRIPTION OF THE INVENTION

In accordance with the present invention, a liquid or solution of atackifying compound is incorporated in an intimate mixture with aparticulate material such as conventional proppants or gravel packingmaterials and introduced into a subterranean formation.

As used in this specification, the term "intimate mixture" will beunderstood to mean a substantially uniform dispersion of the componentsin the mixture. The term "simultaneous mixture" will be understood tomean a mixture of components that are blended together in the initialsteps of the subterranean formation treatment process or the preparationfor the performance of the treatment process.

The coated particulate or proppant material may comprise substantiallyany substrate material that does not undesirable chemically interactwith other components used in treating the subterranean formation. Thematerial may comprise sand, ceramics, glass, sintered bauxite, resincoated sand, resin beads, metal beads and the like. The coated materialalso may comprise an additional material that is admixed with aparticulate and introduced into a subterranean formation to reduceparticulate flowback. In this instance the additional substrate materialmay comprise glass, ceramic, carbon composites, natural or syntheticpolymers or metal and the like in the form of fibers, flakes, ribbons,beads, shavings, platelets and the like. In this instance, theadditional substrate material generally will be admixed with theparticulate in an amount of from about 0.1 to about 5 percent by weightof the particulate.

The tackifying compound comprises a liquid or a solution of a compoundcapable of forming at least a partial coating upon the substratematerial with which it is admixed prior to or subsequent to placement inthe subterranean formation. In some instances, the tackifying compoundmay be a solid at ambient surface conditions and upon initial admixingwith the particulate and after heating upon entry into the wellbore forintroduction into the subterranean formation become a melted liquidwhich at least partially coats a portion of the particulate. Compoundssuitable for use as a tackifying compound comprise substantially anycompound which when in liquid form or in a solvent solution will form anon-hardening coating, by themselves, upon the particulate and willincrease the continuous critical resuspension velocity of theparticulate when contacted by a stream of water as hereinafter describedin Example I by in excess of about 30 percent over the particulate alonewhen present in a 0.5 percent by weight active material concentration.Preferably, the continuous critical resuspension velocity is increasedby at least 40 percent over particulate alone and most preferably atleast about 50 percent over particulate alone. A particularly preferredgroup of tackifying compounds comprise polyamides which are liquids orin solvent solution at the temperature of the subterranean formation tobe treated such that the polyamides are, by themselves, non-hardeningwhen present on the particulates introduced into the subterraneanformation. A particularly preferred product is a condensation reactionproduct comprised of commercially available polyacids and a polyamine.Such commercial products include compounds such as mixtures of C₃₆dibasic acids containing some trimer and higher oligomers and also smallamounts of monomer acids which are reacted with polyamines. Otherpolyacids include trimer acids, synthetic acids produced from fattyacids, maleic anhydride and acrylic acid and the like. Such acidcompounds are available from companies such as Witco Corporation, UnionCamp, Chemtall, and Emery Industries. The reaction products areavailable from, for example, Champion Technologies, Inc. and WitcoCorporation.

In general, the polyamides of the present invention are commerciallyproduced in batchwise processing of polyacids predominately having twoor more acid functionalities per molecule with a polyamine. As is wellknown in the manufacturing industry, the polyacids and polyfunctionalamines are introduced into a reactor where, with agitation, the mildlyexothermic formation of the amide salt occurs. After mixing, heat isapplied to promote endothermic dehydration and formation of the polymermelt by polycondensation. The water of reaction is condensed and removedleaving the polyamide. The molecular weight and final properties of thepolymer are controlled by choice and ratio of feedstock, heating rate,and judicious use of monofunctional acids and amines to terminate chainpropagation. Generally an excess of polyamine is present to preventrunaway chain propagation. Unreacted amines can be removed bydistillation, if desired. Often a solvent, such as an alcohol, isadmixed with the final condensation reaction product to produce a liquidsolution that can readily be handled. The condensation reactiongenerally is accomplished at a temperature of from about 225° F. toabout 450° F. under a nitrogen sweep to remove the condensed water fromthe reaction. The polyamines can comprise, for example, ethylenediamine,diethylenetriamine, triethylene tetraamine, amino ethyl piperazine andthe like.

The polyamides can be converted to quaternary compounds by reaction withmethylene chloride, dimethyl sulfate, benzylchloride, diethyl sulfateand the like. Typically the quaternization reaction would be effected ata temperature of from about 100° to about 200° F. over a period of fromabout 4 to 6 hours.

The quaternization reaction may be employed to improve the chemicalcompatibility of the tackifying compound with the other chemicalsutilized in the treatment fluids. Quaternization of the tackifyingcompound can reduce effects upon breakers in the fluids and reduce orminimize the buffer effects of the compounds when present in variousfluids.

Additional compounds which may be utilized as tackifying compoundsinclude liquids and solutions of, for example, polyesters,polycarbonates and polycarbamates, natural resins such as shellac andthe like.

The surprising discovery has been made that a tackifying compound canalso be produced by the reaction of a polyacid such as previouslydescribed with a multivalent ion such as calcium, aluminum, iron or thelike. Similarly, various polyorganophosphates, polyphosphonates,polysulfates, polycarboxylates, or polysilicates may be reacted with amultivalent ion to yield a tackifying compound. If retardation of therate of reaction is desired, esters of the above compounds may beutilized which will then react with the multivalent ion as the estershydrolyze at the subterranean formation temperatures in the treatmentfluids. Alternatively, chelates may be formed with known chelatingagents such as citric acid, hydroxypropionates and the like to retardthe rate of reaction. Further, it has been found possible to generatethe tackifying compound in-situ within the subterranean formation byintroduction of the polyacid to contact multivalent ions present in thetreatment fluid within the subterranean formation. The multivalent ionsmay be either naturally occurring in the formation or introduced withthe treatment fluid.

The tackifying compound is admixed with the particulate in an amount offrom about 0.05 to about 3.0 percent active material by weight of thecoated particulate. It is to be understood that larger quantities may beused, however, the larger quantities generally do not significantlyincrease performance and could undesirably reduce the permeability ofthe particulate pack. Preferably, the tackifying compound is admixedwith the particulate introduced into the subterranean formation in anamount of from about 0.1 to about 2.0 percent by weight of the coatedparticulate.

When the tackifying compound is utilized with another material that isto be admixed with the particulate and which is to be at least partiallycoated with the tackifying compound, such as glass fibers or the like,the compound is present in an amount of from about 10 to about 250percent active material by weight of the glass fibers or other addedmaterial and generally from about 0.05 to about 3 percent activematerial by weight of the quantity of particulate with which the coatedmaterial is intimately admixed. Preferably the tackifying compound ispresent in an amount of from about 10 to about 150 percent of thematerial which is to be at least partially coated with the tackifyingcompound and then added to the particulate. At least a portion of thetackifying compound introduced with the additional material will contactand coat at least a portion of the particulate with which it is admixed.

The liquid or solution of tackifying compound interacts mechanicallywith the particles of particulate introduced into the subterraneanformation and the adhered fines to limit or prevent the flowback offines to the wellbore.

The liquid or solution of tackifying compound generally is incorporatedwith the particulate in any of the conventional fracturing or gravelpacking fluids comprised of an aqueous fluid, an aqueous foam, ahydrocarbon fluid or an emulsion, a viscosifying agent and any of thevarious known breakers, buffers, surfactants, clay stabilizers or thelike.

Generally the tackifying compound may be incorporated into fluids havinga pH in the range of from about 3 to about 12 for introduction into asubterranean formation. The compounds are useful in reducing particulatemovement within the formation at temperatures from about ambient to inexcess of 275° F. It is to be understood that not every tackifyingcompound will be useful over the entire pH or temperature range butevery compound is useful over at least some portion of the range andindividuals can readily determine the useful operating range for variousproducts utilizing well known tests and without undue experimentation.

It has been discovered that the incorporation of or addition of certainsurfactants to the fluid suspension can improve or facilitate thecoating of the tackifying compound upon the particulate. The addition ofselected surfactants has been found to be beneficial at both elevatedfluid salinity and elevated fluid pH as well as at elevatedtemperatures. The surfactants appear to improve the wetting of theparticulates by the tackifying compound. Suitable surfactants include:nonionics, such as, long chain carboxylic esters such as propyleneglycol, sorbitol and polyoxyethylenated sorbitol esters,polyoxyethylenated alkylphenols, alkyphenol, ethoxylates,alkyglucosides, alkanolamine condensates and alkanolamides; anionics,such as, carboxylic acid salts, sulphonic acid salts, sulfuric estersalts and phosphonic and polyphosphoric acid esters; cationics, such as,long chain amines and their salts, quaternary ammonium salts,polyoxyethylenated long chain amines and quaternized polyoxyethylenatedlong chain amines; and zwitterion, such as n-alkylbetaines.

The liquid or solution of tackifying compound generally is incorporatedwith the particulate as a simultaneous mixture by introduction into thefracturing or gravel packing fluid along with the particulate.Fracturing fluids are introduced into the subterranean formation at arate and pressure sufficient to create at least one fracture in theformation into which particulate then is introduced to prop the createdfracture open to facilitate hydrocarbon production. Gravel packingtreatments generally are performed at lower rates and pressures wherebythe fluid can be introduced into a formation to create a controlledparticle size pack surrounding a screen positioned in the wellborewithout causing fracturing of the formation. Alternatively the gravelpack may be performed without a screen, if consolidatable particulate isutilized, and the pack may fill the wellbore. Thereafter, the pack maybe drilled out, flushed or reamed to open a passage in the bore, ifnecessary. The particulate pack surrounding the wellbore then functionsto prevent fines or formation particulate migration into the wellborewith the production of hydrocarbons from the subterranean formation. Thetackifying compound may be introduced into the fluid before, after orsimultaneously with introduction of the particulate into the fluid. Whenthe tackifying compound is generated in-situ in the formation, thereactants may be introduced individually as described above for thetackifying compound and the multivalent ion source may be naturallyoccurring or introduced into the formation. The liquid or solution maybe incorporated with the entire quantity of particulate introduced intothe subterranean formation or it may be introduced with only a portionof the particulate, such as in the final stages of the treatment toplace the intimate mixture in the formation in the vicinity of thewellbore. For example, the tackifying compound may be added to only thefinal 20 to 30 percent of the particulate laden fluid introduced intothe formation. In this instance, the intimate mixture will form atail-in to the treatment which upon interaction within the formationwith the particulate will cause the particles to bridge on theagglomerates formed therein and prevent movement of the particles intothe wellbore with any produced fluids. The tackifying compound may beintroduced into the blender or into any flowline in which it willcontact the material to be at least partially coated by the compound.The compound may be introduced with metering pumps or the like prior toentry of the treatment fluid into the subterranean formation.

In an alternate embodiment, the particulate may be premixed with thetackifying compound prior to admixing with a treatment fluid for use ina subterranean formation.

The surprising discovery has been made that when a polyamide is utilizedas the tackifying compound, ferrous metal in contact with the treatmentfluid has been found to exhibit extended corrosion inhibition. It hasbeen determined that minute amounts of the polyamide are dissolved fromthe coated particulate by hydrocarbons flowing through the formation andinto the wellbore and that such quantities provide extended corrosionprotection to the ferrous metals contacted thereby and that also are incontact with aqueous fluids introduced into or produced from thesubterranean formation. The polyamide material appears to coat or form avery thin film on the ferrous metal surfaces protecting them fromcontact with aqueous fluids.

In yet another embodiment of the invention wherein a previouslyperformed fracturing treatment or gravel pack is producing back proppantor formation fines with the production of hydrocarbons, a remedialparticulate control treatment may be performed. In this instance, thetackifying compound is admixed with a diluent, such as for example,crude oil, distillates, butyl alcohol, isopropyl alcohol, a heavyaromatic solvent such as xylene, toluene, heavy aromatic naptha or thelike, mutual solvents such as ethylene glycol monobutyl ether, propylenecarbonate or n-methylpyrolidone or the like. The tackifying compoundgenerally will be present in an amount of from about 0.5 to about 30percent by volume of the solution to be used to treat the subterraneanformation. The tackifying compound also may be admixed with selectedsurfactants and other additives that do not adversely react with thecompound to prevent fines control. The tackifying compound containingsolution is introduced into the subterranean formation preferably at arate and pressure below the fracture gradient for the subterraneanformation. The tackifying compound tends to contact and at leastpartially coat at least a portion of the proppant or gravel whichpreviously has been introduced into the formation.

The coating of the proppant or gravel causes the larger particles tosubsequently tend to adhere to one another resulting in the formation ofparticulate bridges in the formation upon the resumption of hydrocarbonproduction. As fines in the produced fluids contact the tackifyingcompound coated particulates in the subterranean formation, the finestend to become bound to the larger particulates and are prevented frommigrating through the proppant or gravel pack with producedhydrocarbons. Introduction of the tackifying compound solution into thesubterranean formation at matrix flow rates (rates below that necessaryto exceed the fracture gradient and cause fracture formation) tends tominimize the possibility of additional fines release within theformation. If it is desired to redistribute proppant in a subterraneanformation or reopen or extend fractures into the subterranean formation,the tackifying compound solution can be introduced into the subterraneanformation at a rate and pressure sufficient to fracture the subterraneanformation. Any fines that may be produced as a result of the fracturingoperation tend to become bound to and adhere to the particulate that isat least partially coated by the tackifying compound as it is depositedwithin the subterranean formation.

To further illustrate the present invention and not by way oflimitation, the following examples are provided.

EXAMPLE I

The evaluation of a liquid or solution of a compound for use as atackifying compound is accomplished by the following test. A criticalresuspension velocity is first determined for the material upon whichthe tackifying compound is to be coated. Referring now to FIG. 1, a testapparatus is illustrated for performing the test. The apparatuscomprises a 1/2" glass tee 10 which is connected to an inlet source 12of water and an outlet 14 disposal line is blocked to fluid flow. Awater slurry of particulate is aspirated into the tee 10 through inlet12 and collected within portion 16 by filtration against a screen 18.When portion 16 of tee 10 is full, the vacuum source is removed and aplug 20 is used to seal the end of portion 16. The flow channel frominlet 12 to outlet 14 then is swabbed clean and a volumetricallycontrolled pump, such as a "MOYNO" pump, is connected to inlet 12 and acontrolled flow of water is initiated. The velocity of the fluid isslowly increased through inlet 12 until the first particle ofparticulate material is picked up by the flowing water stream. Thisdetermines the baseline for the starting of the resuspension velocity.The flow rate then is further increased until the removal of particlesbecomes continuous. This determines the baseline for the continuousresuspension velocity. The test then is terminated and the apparatus isrefilled with particulate having a coating corresponding to about 0.5percent active material by weight of the particulate applied thereto.Similar trends generally are seen in the results when the concentrationstested are from about 0.1 to about 3 percent, however, the 0.5 percentlevel which is within the preferred application range is preferred forstandardization of the procedure. The test is repeated to determine thestarting point of particulate removal and the velocity at which removalbecomes continuous. The percent of velocity increase (or decrease) thenis determined based upon the initial or continuous baseline value. Theresults of several tests employing the preferred polyamide of thepresent invention, and conventional epoxy and phenolic resins known foruse in consolidation treatments in subterranean formations with 12/20and 20/40 mesh sand are set forth below in Table I.

                  TABLE I                                                         ______________________________________                                                          Coating Agent,                                                                             Percent Of Velocity                            Test    Particulate                                                                             % V/Wt       Change At                                      No.     Size      Particulate  Starting                                                                            Continous                                ______________________________________                                        1       20/40/mesh                                                                              none         0      0                                               sand                                                                  2       20/40 mesh                                                                              1/2 percent  192    222                                             sand      polyamide                                                   3       20/40 mesh                                                                              1 percent    271    391                                             sand      polyamide                                                   4       20/40 mesh                                                                              1/2 percent  -0.5   6.5                                             sand      phenolic                                                    5       20/40 mesh                                                                              1 percent    -9     -6.8                                            sand      phenolic                                                    6       20/40 mesh                                                                              1/2 percent  -9     -1.2                                            sand      epoxy                                                       7       20/40 mesh                                                                              1 percent    5.2    12.2                                            sand      epoxy                                                       8       12/20 mesh                                                                              1/2 percent  228    173                                             sand      polyamide                                                   9       12/20 mesh                                                                              1 percent    367    242                                             sand      polyamide                                                   10      12/20 mesh                                                                              1/2 percent  42     22                                              sand      phenolic                                                    11      12/20 mesh                                                                              1 percent    42     13                                              sand      phenolic                                                    12      12/20 mesh                                                                              1/2 percent  48     30                                              sand      epoxy                                                       13      12/20 mesh                                                                              1 percent    38     15                                              sand      epoxy                                                       ______________________________________                                    

The data clearly illustrates the substantial increase in the criticalresuspension velocity of a particulate coated with the tackifyingcompound in comparison to other known formation consolidation agentswhich require hardening to be effective.

EXAMPLE II

To illustrate the ability of the tackifying compound to control fines,the following tests were performed.

Two sand slurries were prepared and placed in 1 inch diameter, 36 inchtall glass columns having a screen and a one hole plug stopper at theirlower ends which was sealed off. The slurries comprised 250 ml. of a 25lb/1000 gallon hydrated guar, 300 grams 20/40 mesh Brady sand containing7.4% by weight of 50 mesh and smaller fines material, 0.5 ml enzymebreaker and 0.5 ml. borate crosslinker. One percent by weight of thetackifying compound of the present invention was added to the secondslurry.

The slurries were allowed to sit static for 48 hours. The first columnsettled to a height of 21.125 inches and the tackifying compoundcontaining sample settled to a height of 21.875, inches.

The broken fluids were removed from the columns above the settled sandin the columns and replaced with water. The columns were attached to aconstant head water supply. While maintaining the water supply constant,the hole in the bottom stopper was opened, water flow rates andpermeabilities were determined. The sand packs had settled during thewater flow to 20.5 inches and 21.625 inches respectively.

The flow was resumed, using kerosene and flow rates and permeabilitieswere determined. Pack heights settled to 20.125 inches and 21.437inches, respectively.

The difference in the permeability of the packs in the columns isillustrated in the chart comprising FIG. 2. The difference in the finalpack height is an indication of the agglomeration of the fines with thelarger particles preventing close packing by fines movement as occurs inthe untreated column. The lower permeability of the untreated pack alsoindicates fines migration has occurred.

The stabilization properties of the method of the present invention alsoare determined by flow through an American Petroleum Institute approvedsimulated fracture flow cell.

The cell contains Ohio sandstone cores having a proppant bed size ofabout 1.5 inches in height, about 7 inches in length and about 0.25inches in width between the cores. The bed is initially prepacked with20/40 mesh sand by introducing the sand into the cell in an aqueousslurry or a gelled fluid containing 40 pounds of guar per 1000 gallonsof aqueous fluid. The cell is fitted with a 0.3 inch hole at one end tosimulate a perforation. The hole is visible through a sight glass sothat proppant production, if any, through the hole can be visuallydetermined.

The conductivity of the pack is determined at a stress loading of 2000and 3000 psi for the untreated sand.

The cell then was cleaned and packed with another proppant packcontaining 0.5 percent by weight tackifying compound for testing. Theresults of the tested materials are set forth in Table II, below.

                  TABLE II                                                        ______________________________________                                                   CONDUCTIVITY, mD/ft at                                                        2000 psi loading                                                                        3000 psi loading                                         ______________________________________                                        untreated sample                                                                           4251        3487                                                 treated sample                                                                             5130        3829                                                 ______________________________________                                    

FIG. 3 presents photomicrographs of a portion of the sand packs from theuntreated and treated samples after removal from the flow cell. Thedifference in the free fines content of the two samples is readilyapparent in the photos. The untreated sample contains significantquantities of free fines whereas the fines are found to be primarilyattached to the larger sand particles in the treated sample.

EXAMPLE III

To illustrate the effectiveness of the tackifying compound incontrolling fines, the following turbidity tests were performed. Aseries of samples were prepared containing a quantity of 100 grams of20/40 Brady frac sand admixed with 100 ml of tap water. A selectedquantity of tackifying compound was admixed with a sample and theturbidity of the solution was determined. The turbidity was measured inFormazin Turbidity Units utilizing a Coleman Junior IISpectrophotometer, Model 6-20. The results are set forth in Table III,below.

                  TABLE III                                                       ______________________________________                                                  TACKIFYING COMPOUND,                                                                           TURBIDITY,                                         SAMPLE    ml               FTU                                                ______________________________________                                        1         0                43                                                 2         0.25             38                                                 3         0.5              18                                                 4         1.0              12                                                 ______________________________________                                    

The tests were repeated using 20/40 Brady frac sand to which is added0.2 grams of silica flour to simulate a high fines content. Theturbidity was measured as previously described. The results are setforth in TABLE IV, below.

                  TABLE IV                                                        ______________________________________                                                  TACKIFYING COMPOUND,                                                                           TURBIDITY,                                         SAMPLE    ml               FTU                                                ______________________________________                                        1         0                337                                                2         0.25             137                                                3         0.5               56                                                4         1.0               29                                                ______________________________________                                    

The data clearly illustrates the ability of the compound to controlfines movement in the fluid and to bind the fines to proppant materialswhich are coated by the tackifying compound.

EXAMPLE IV

To illustrate the effect of the tackifying compound on controlling finesmigration in coal seams two treatments are performed on adjacent wellsin Colorado on a gas containing coal seam producing at a depth of fromabout 1850 to about 2100 ft. at a bottomhole temperature of about 110°F. The treatments are performed down 5 1/2 inch casing. The treatmentscomprised approximately 2000 gallons of 15% acetic acid, 24,000 gallonsof a guar containing pad, 60,000 gallons of a fracturing treatmentincluding approximately 300,000 pounds of 12/20 sand and 2000 gallons offlush fluid. The fracturing fluid comprised a borate crosslinked fluidcontaining 20 lbs guar per 1000 gallons of fluid. The fluid alsocontained clay control additives, surfactants, gel breakers and biocide.One treatment included approximate 1.0 percent tackifying compound addedto the sand during performance of the treatment.

The initial production of the wells was about 180 MCF per day and about180 BWPD. Post frac production after cleanup of fracturing treatmentfluid on the well without fines control is about 500 MCF and about 400BWPD. The well having the treatment utilizing fines control techniquesof the present invention after clean up of fracturing treatment fluid isproducing about 800 MCF per day and about 600 BWPD. The first well isproducing fracturing treatment sand and coal fines into the wellborealong with the production of gas. The well treated with the tackifyingcompound is not producing measurable amounts of fines or fracturingtreatment sand.

EXAMPLE V

To illustrate the corrosion inhibition of a film of the tackifyingcompound comprising polyamides, the following tests were performed oncarbon steel coupons weighing approximately 1 gram at 160° F. insimulated sweet and sour well conditions.

Test fluids are placed in sealed bulk containers and purged for aminimum of six hours with carbon dioxide. For sour gas tests, H₂ S thenis bubbled into the container for 15 to 20 minutes. The proper amount ofpolyamide is dispensed by syringe into each test bottle. The testbottles are 7 ounce capacity. The blank samples contain no polyamide.Each bottle is purged with carbon dioxide to displace air and apreviously weighed and cleaned sample coupon is placed in the bottle. Aquantity of 108 ml of NACE brine and 12 ml of kerosene then are added tothe bottles from the purged bulk containers. The bottles are capped andplaced on a rotating wheel and rotated for 1 hour at 160° F.±10° F. Thebottles then are removed from the wheel and the coupons are transferredto bottles containing brine and kerosene without inhibitor under acarbon dioxide purge to rinse the coupons. The blanks are nottransferred since the blank sample bottles contain no inhibitor. Thebottles are returned to the rotating wheel for an additional hour. Thebottles then are removed from the wheel and the coupons are transferredto bottles having the same brine and kerosene mix without the polyamide.The transfer is effected under a carbon dioxide purge and the bottlesare returned to the wheel for an additional 72 hours at about 160° F. todetermine corrosion effects on the samples. Samples containing H₂ S werereturned to the wheel only for 24 hours. After completion of theexposure time, the coupons are retrieved from the bottles, cleaned,dried and weighed. The corrosion loss then is determined. Each sample isrun in triplicate and the values are averaged to determine the loss fora sample condition. The results of the tests are set forth in Table Vbelow.

                  TABLE V                                                         ______________________________________                                                Polyamide                                                                     Concentration,         Corrosion Rate,                                Sample  ppm          H.sub.2 S Present                                                                       lbs/ft2                                        ______________________________________                                        1         0          No        8.564                                          2       2500         No        1.233                                          3        50          No        1.103                                          4         0          Yes       3.193                                          5       2500         Yes       0.183                                          6        50          Yes       0.455                                          ______________________________________                                    

The polyamide film formed on the ferrous metal surface in contact withthe aqueous fluid provided significant corrosion protection incomparison to samples having no film as a result of contact with thetackifying compound.

While the present invention has been described with regard to that whichis currently considered to comprise the preferred embodiments of theinvention, other embodiments have been suggested and still otherembodiments will occur to those individuals skilled in the art uponreceiving the foregoing specification. It is intended that all suchembodiments shall be included within the scope of the present inventionas defined by the claims appended hereto.

What is claimed is:
 1. A method of treating a subterranean formation tocontrol corrosion of ferrous metals in contact therewith by aqueousfluids comprising the steps of:introducing a particulate-containingfluid suspension into a subterranean formation through a wellborepenetrating the formation; admixing with at least a portion of saidparticulate in said fluid suspension an effective amount of a tackifyingcompound comprising a polyamide whereby at least a portion of saidparticulate is at least partially coated by said tackifying compound;depositing said tackifying compound coated particulate in thesubterranean formation; and flowing back fluid from the subterraneanformation whereby a portion of the tackifying compound is caused to bedisplaced from said coated particulate and to contact at least a portionof a surface of a ferrous metal in contact with said formation andthereby protect at least a portion of said surface from corrosion causedby aqueous fluids in contact therewith.
 2. The method of claim 1 whereinsaid polyamide comprises predominately a condensation reaction productof a dimer acid containing some trimer and higher oligomers and somemonomer acids and a polyamine.
 3. The method of claim 1 wherein saidtackifying compound is present in an amount of from about 0.05 to about3% by weight of said particulate.
 4. The method of claim 1 wherein priorto introducing said coated particulate the following step is performed,comprisingintroducing a treatment fluid into said subterranean formationat a rate and pressure sufficient to create at least one fracture insaid subterranean formation.
 5. The method of claim 4 wherein prior tointroducing the coated particulate and after the fracture is created, aquantity of particulate is introduced into said fracture followed bysaid tackifying compound coated particulate.
 6. The method of claim 2wherein said polyamine comprises at least one member selected from thegroup of ethylenediamine, diethylenetriamine, triethylenetetraamine,tetraethylene pentaamine and aminoethylipiperazine.
 7. A method oftreating a subterranean formation to control corrosion of ferrous metalsin contact therewith by aqueous fluids in said formation comprising thesteps of:introducing a solution of an effective amount of a tackifyingcompound comprising a polyamide and a diluent into a subterraneanformation to contact particulates present in said subterraneanformation; depositing at least a portion of said tackifying compoundupon at least a portion of said particulates in said subterraneanformation; and flowing aqueous fluid from said subterranean formationwhereby a portion of the deposited tackifying compound is caused to bedisplaced from said particulates and to subsequently contact at least aportion of a ferrous metal surface in contact with said formation andthereby protect at least a portion of said surface from corrosion causedby aqueous fluids in contact therewith.
 8. The method of claim 7 whereinsaid polyamide comprises predominately a condensation reaction productof a dimer acid containing some trimer and higher oligomers and somemonomer acids and a polyamine.
 9. The method of claim 8 wherein saidtackifying compound comprises predominately a condensation reactionproduct of a dimer acid containing some trimer and higher oligomers andsome monomer acids with a polyamine.
 10. The method of claim 7 whereinsaid tackifying compound is present in an amount of from about 0.05 toabout 3% by weight of said particulate.
 11. The method of claim 7defined further to include the step of:introducing a treatment fluidinto said subterranean formation at a rate and pressure sufficient tocreate at least one fracture in said subterranean formation.
 12. Themethod of claim 11 wherein a particulate is admixed with at least aportion of said treatment fluid and said particulate is introduced intosaid created fracture and at least a portion of said particulate isdeposited in said created fracture.
 13. The method of claim 12 whereinan effective amount of said tackifying compound is admixed with saidparticulate in said treatment fluid prior to introduction into saidfracture whereby said tackifying compound is present in an amount offrom about 0.05 to about 3% by weight of said particulate in saidtreatment fluid.
 14. The method of claim 13 wherein prior tointroduction of said tackifying compound coated particulate in saidtreatment fluid into said created fracture a quantity of uncoatedparticulate is introduced into said fracture.
 15. The method of claim 14wherein after introduction of said tackifying compound coatedparticulate a quantity of uncoated particulate is introduced into saidcreated fracture followed by an additional quantity of said tackifyingcompound coated particulate.